Tag: Oil and Gas

Saudi Arabia’s fiscal breakeven oil price is rising fast. What will the kingdom do about it?

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An offshore drilling platform stands in shallow waters at the Manifa offshore oilfield, operated by Saudi Aramco, in Manifa, Saudi Arabia, on Wednesday, Oct. 3, 2018.

Simon Dawson | Bloomberg | Getty Images

Saudi Arabia has a superpower. Not only is it the largest exporter of crude oil in the world; its production costs for oil projects are also the lowest in the world, at around just $10 per barrel. When around 75% of your fiscal revenue comes from oil, that’s a big deal.

And for a time, its fiscal breakeven oil price — what it needed a barrel of crude to cost in order to balance its government budget — was fairly comfortable, too.

That’s changing as the kingdom embarks on huge spending projects as part of Vision 2030, which aims to modernize its economy and diversify its revenue sources away from oil. With each passing year, that projected fiscal breakeven oil price gets higher, and the kingdom’s deficit widens.

In May of 2023 the International Monetary Fund forecast the kingdom’s breakeven oil price at $80.90 per barrel, which moved it back into a fiscal deficit following its first surplus in nearly a decade. To be sure, the fiscal breakeven isn’t the price at which Saudi Arabia makes a profit on crude but the average oil price it needs to balance the books.

The IMF’s latest forecast, in April, put that breakeven figure at $96.20 for 2024; a roughly 19% increase on the year before, and about 32% higher than the current price of a barrel of Brent crude, which is trading at around $73 as of Wednesday afternoon.

Riyadh, Saudi Arabia.

Johnnygreig | E+ | Getty Images

“At least until 2030, Saudi will have massive budgetary needs due to the need to demonstrate some significant outcome in key Vision 2030 projects and to prepare for and host big sporting and cultural events” like the World Cup 2034 and Expo 2030, said Li-Chen Sim, a non-resident scholar at the Washington-based Middle East Institute.

“All this amidst expected growth in oil supply from the U.S., Guyana, Brazil, Canada, and even the UAE and possible anemic oil consumption growth in China, the Kingdom’s largest oil customer, means that the Kingdom’s fiscal breakeven price is likely to rise perhaps to around $100.”

All that, she adds, does not include the domestic spending requirements of the kingdom’s mammoth sovereign wealth fund, the Public Investment Fund, which is behind multi-trillion dollar megaprojects like NEOM. A Bloomberg forecast cited by Nomura Asset Management put this year’s breakeven price, including PIF spending, at $112 per barrel.

“Saudi Arabia is wealthy and government spending has climbed rapidly over the past decade but it has fiscal parameters within which it must operate just like every other country,” a Nomura report on Arabian markets published Sept. 2 read.

Important economic indicators “like oil production and prices, are now flashing warning signs,” it added. “A global slowdown amid supply uncertainties may hamper prospects for hydrocarbon economies.”

Saudi Arabia’s economy swung dramatically from a budget surplus of $27.68 billion in 2022 to a deficit of $21.6 billion in 2023 as it ramped up public spending and decreased oil production due to its OPEC+ supply cut agreement. Its government forecasts a deficit (meaning the total amount of money spent will be more than the money received) of $21.1 billion for 2024, projecting revenue at $312.5 billion and expenditures at $333.5 billion.

Does the breakeven oil price actually matter?

But wait — fiscal breakeven prices are not always as important as people think they are, some economists and market analysts argue. And for Saudi Arabia, a range of options exist to manage deficits and less-than-ideal oil prices.

“The reality is that countries run deficits all the time, and therefore the idea Saudi Arabia needs $112 oil, or whatever the number is, to me doesn’t provide a true representation of what’s going on,” one energy analyst who focuses on the kingdom told CNBC.

“For Saudi Arabia, they have a lot of capacity to take on more debt if they wanted to … it’s not an issue for them to run a small deficit,” the analyst said, speaking anonymously due to professional restrictions on speaking to the press.

The kingdom also has robust foreign currency reserves, which grew to a 20-month high of $452.8 billion in July, and has been successfully issuing bonds, tapping debt markets for $12 billion so far this year. Oil revenue should increase in 2025 when the OPEC+ production cuts, the majority of which were taken by Saudi Arabia, expire, according to energy analysts.

“From that perspective, they’re also starting from a relatively strong position,” the source said.

Saudi Arabia’s public debt has grown from around 3% of its GDP in the 2010s to 24% today — that’s a massive increment, Sim said. But by international standards, it’s still low. Average public debt in EU countries, for instance, averages 82%. In the U.S. in 2023, that figure was 123%.

Watch CNBC's interview with Saudi Arabia's assistant minister of investment

Its relatively low debt level and high credit rating makes it easier for Saudi Arabia to take on more debt as it needs to. The kingdom has also rolled out a series of reforms to boost and de-risk foreign investment and diversify revenue streams. While the country’s economy has contracted for the last consecutive four quarters, non-oil economic activity grew 4.4% in the second quarter year-on-year, up 3.4% from the prior quarter.

“The good news is that the economy is progressing along its diversification track and has already absorbed large reductions in subsidies and higher VAT while generating a huge number of jobs,” the Nomura report said.

While the kingdom “still lacks the quantum of foreign direct investments desired,” it wrote, “the newly approved investment law should bring it closer to achieving its goal of building a substantially bigger non-oil sector.”

Risks remain, however — primarily if oil demand continues to be soft in major consuming countries and crude supply in non-OPEC+ countries continue to grow, Sim said. And those risks are entirely out of Saudi Arabia’s control.

“With regard to the first point, the biggest danger is a possible tit-for-tat tariff war between China and the US or Europe,” Sim said. This “could result in slower global economic growth and hence a reduced demand for oil.”

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AI demand could strain electrical grid in coming decade

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Power lines and transmission towers near the Ivanpah Solar Electric Generating System in the Mojave Desert in San Bernardino County, California, U.S., on Saturday, Feb. 19. 2022.

Bloomberg | Bloomberg | Getty Images

Artificial intelligence could strain the U.S. electric grid, as power demand from data centers is poised to surge in the coming decade just as supply is falling due to the rapid retirement of coal-fired plants.

Data centers in the U.S. alone could consume as much electricity as some major industrialized economies produce by 2030, as they proliferate not just in number but also in the scale of their power needs.

The computer warehouses that power the Internet and increasingly AI could require up to 400 terawatt hours of electricity by 2030, according to an August report from Mizuho Securities.

That’s more than the total electricity production of the United Kingdom in 2022, according to data from the International Energy Agency.

Data center developers are knocking at the door of the nation’s utilities at the same time many of these power companies are retiring coal plants as part of the transition away from fossil fuels. But the waiting list to bring clean energy, primarily solar and wind, onto the grid to replace coal is long and renewables are less reliable.

PJM Interconnection, the largest grid operator in the U.S., warned in July that the reliability of the system is a growing concern as coal plants close faster than new power generation is built.

PJM serves 13 states primarily in the Mid-Atlantic region, including northern Virginia, the largest data center market in the world. Resources in areas of Virginia are insufficient and the transmission system is constrained, limiting the ability to import power from elsewhere, according to PJM.

Yet data center “growth is accelerating in orders of magnitude, driven by the number of requests, the size of each facility and the acceleration of each facility’s ramp schedule to reach full capacity,” Dominion Energy CEO Robert Blue told investors on the company’s earnings call on Aug. 1.

Electrification of economy

In addition to data centers, manufacturing is returning to the U.S. and the broader economy is electrifying. Recent auction prices to bring new power capacity to the PJM power pool have surged more than 800% as a consequence of rising demand and limited supply.

“The market has already made one transition from coal to gas,” Susan Buehler, a spokesperson for PJM, told CNBC. “We see this energy transition is here. We just see that the forces around it are happening faster than the renewable energy transition is happening.”

“So we see a potential gap, and that’s what the market is signaling,” Buehler said.

PJM has forecast that electricity demand surge will surge nearly 40% by 2039 in its 369,000-square mile service area. Meanwhile, 40 gigawatts of existing power generation is at risk of retirement by 2030, or about 21% of PJM’s current installed capacity.

While there are 290 gigawatts of renewable projects waiting to get connected to the grid, in the past only about 5% of such projects have actually been built, according to PJM.

About 38 gigawatts of renewable energy have been approved for connection and another 72 gigawatts are coming in the first quarter of 2025, Buehler said, but the projects are not being built quickly enough due the challenges developers are facing on the ground.

Buehler said developers “can’t get their projects sited, there are supply chain delays, and there are financing issues.”

Step-change in investment needed

Utilities that operate in PJM have disclosed at least 50 gigawatts of potential data center demand during their recent earnings calls, though CEOs have cautioned there could be some duplication in the numbers.

About 29% of current data center electricity demand in the U.S. is located within PJM’s territory, according to Mizuho. Some 25% of data center power demand in the nation is in Virginia.

American Electric Power, one of the largest electric utilities in the U.S., has commitments for more than 15 gigawatts of demand from data centers through the end of the decade, interim CEO Benjamin Fowke told investors on the company’s second-quarter earnings call earlier last month.

That level of demand is equivalent to more than 40% of the peak electric load of 35 gigawatts across AEP’s entire system at the end of last year, according to Fowke. AEP serves 5.6 million customers in 11 states in the Midwest and South.

“These are far from just inquiries,” Fowke told investors. “These are serious customers that want to get on the grid and are willing to financially commit to do what it takes to get on the grid.”

Fowke testified to Congress in May that demand for electricity in some parts of the U.S. is already outstripping available capacity on the grid. The former CEO of Xcel Energy said that requests from large customers would more than double the current peak demand on the utility’s system.

“It took over 100 years of planning and building to create our current system, and a step-change in infrastructure investment on an accelerated timeline will be required to serve even a fraction of this future demand in a reliable manner,” Fowke told the Senate Committee on Energy and Natural Resources.

The cost of building new infrastructure to meet the demand is expected to reach hundreds of billions of dollars, Fowke said.

In the past, a large manufacturing facility might need 100 megawatts of electricity — equivalent to about 100,000 homes, Fowke told Congress. It is now increasingly common for a single data center to need anywhere from three to 15 times that amount of power, the CEO said.

Dominion Energy regularly gets requests to support data center campuses that require as much as several gigawatts of power, Blue said in May. That’s larger than the average capacity of a nuclear reactor in the U.S.

Going around the grid

One of the many challenges in connecting this kind of demand to the grid is that it can take up to a decade to decide the exact route a transmission line will take, get the necessary permits and build it, Edison Electric Institute senior vice president for customer solutions Phil Dion told Congress in June.

As a result, tech companies that are building data centers are increasingly looking at directly connecting their facilities to large power resources, such as nuclear plants, rather than waiting to access the grid. But that approach is already facing controversy.

Amazon Web Services purchased a data center campus in March from Talen Energy for $650 million that will be powered directly by the Susquehanna nuclear plant in Pennsylvania. It was viewed by some in the industry as a landmark agreement that could pave the way for more nuclear-powered data centers.

But AEP has challenged the agreement before the Federal Energy Regulatory Commission, warning that such arrangements could further constrain supply on the electric grid.

Constellation Energy CEO Joe Dominguez told investors earlier this month that hooking data centers directly to nuclear reactors is the fastest and most cost effective solution. Constellation operates the largest portfolio of nuclear plants in the U.S.

“The notion that you could accumulate enough power somewhere on the grid to power a gigawatt data center is frankly laughable to me,” Dominguez said on Constellation’s August earnings call.

Utility executives have warned that failure to meet rising demand from data centers could affect the entire U.S. economy.

“If I can’t get that power capacity online, I cannot do the data center. I cannot do the manufacturing. I can’t grow the core businesses of some of the largest corporations in the country,” Petter Skantze, vice president of infrastructure development at NextEra Energy Resources, the renewable energy unit of NextEra Energy, said at a conference in New York City in June.

“The stakes are really, really high,” Skantze said. “This is a new environment. We have to get this right.”

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Tech companies want nuclear power. Some utilities are throwing up roadblocks

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A cooling tower at the Constellation Nine Mile Point Nuclear Station in Scriba, New York, US, on Tuesday, May 9, 2023. 

Lauren Petracca | Bloomberg | Getty Images

Tech companies are increasingly looking to directly connect data centers to nuclear plants as they race to secure clean energy to power artificial intelligence, sparking resistance from some utilities over the potential impact on the electric grid.

Data centers, the computer warehouses that run the Internet, in some cases now require a gigawatt or more of power, comparable to the average capacity of a nuclear reactor in the U.S.

The data centers are essential to U.S. economic competitiveness and national security as the country competes with adversaries such as China for supremacy in the race to develop AI, said Joe Dominguez, the CEO of Constellation Energy, which operates the largest nuclear fleet in the U.S.

“When you’re talking about large [demand] load that also wants to use zero-emission energy, you’re going to bring it very close to nuclear power plants,” Dominguez said on Constellation’s second-quarter earnings call Tuesday. Constellation, headquartered in Baltimore, operates 21 of the 93 reactors in the U.S.

Constellation’s shares have surged 62% this year, the sixth-best stock in the S&P 500, as investors attach a higher value to the company’s nuclear power capacity to meet the growth in data centers. Shares of Vistra Corp., based outside Dallas and owner of six reactors, have doubled this year, the second-best performing stock in the S&P after AI chipmaker Nvidia.

Tech companies are building out data centers just as power supply is increasingly constrained due to the retirement of coal plants and as demand is climbing from the expansion of domestic manufacturing and the electrification of vehicles.

The largest grid operator in the U.S., PJM Interconnection, warned in late July that power supply and demand is tightening as construction of new generation lags demand. PJM covers 13 states primarily in the Mid-Atlantic region, including the world’s largest data center hub in northern Virginia.

Constellation’s Dominguez argued that connecting data centers directly to nuclear plants, called co-location by the industry, is the fastest and most cost-effective way to support the buildout of data centers, without burdening consumers with the costs of building new transmission lines.

“The notion that you could accumulate enough power somewhere on the grid to power a gigawatt data center is frankly laughable to me — that you could do that in anywhere that doesn’t start with decades of time,” Dominguez said. “This is an enormous amount of power to go out and try to concentrate.”

Amazon’s nuclear agreement

But co-locating data centers next to nuclear plants already faces controversy.

In March, Amazon Web Services bought a data center powered by the 41-year-old Susquehanna nuclear plant in Pennsylvania from Talen Energy for $650 million . But the agreement to directly sell power to the AWS data center from the nuclear plant already faces opposition from utilities American Electric Power and Exelon, who have filed complaints at the Federal Energy Regulatory Commission (FERC).

AEP and Exelon argue that the deal between Amazon and Talen sets a precedent that will result in less available power in the PJM grid area as resources “flee to serve load that uses and benefits from — but does not pay for — the transmission system”

“This will harm existing customers,” the utilities told FERC in a filing in June. Talen Energy has dismissed the objections as “demonstrably false,” accusing the utilities of stifling innovation.

“The rapid emergence of artificial intelligence and data centers has fundamentally changed the demand for power and leads to an inflection point for the power industry,” Talen said in a June statement. “Talen’s co-location arrangement with AWS brings one solution to this new demand, on a timeline that serves the customer quickly.”

FERC has requested more information on the service agreement between Talen and AWS. The regulator is holding a conference in the fall to discuss issues associated with connecting large electricity loads directly to power plants.

“It really is a great opportunity for there to be interaction between stakeholders and the commissioners in an informal setting like a conference, as opposed to doing so in litigation,” Kathleen Barrón, chief strategy officer at Constellation, said on the power company’s recent earnings call, referring to the fall FERC meeting.

Shopping for nuclear power

Constellation and Vistra have backed the AWS-Talen agreement in filings to FERC, with each of their CEOs saying on their earnings calls this week that co-location and traditional grid connection will be needed to meet demand.

Barrón told CNBC that Constellation has “seen interest from many” tech companies in potentially co-locating a data center at one of its sites.

Vistra is having numerous conversations with customers about co-location and is “in due diligence for a number of sites,” CEO Jim Burke said Thursday. With the dispute in the PJM region over co-location, data center developers may take a closer look at Texas, which operates its own grid called ERCOT, Burke said.

“We’re seeing some interest in Comanche Peak,” Burke told analysts on the company’s second-quarter earnings call, referring to one of Vistra’s nuclear plants. Comanche Peak, about 50 miles outside Fort Worth, Texas, has two reactors with 2.4 gigawatts of capacity, enough to power 1.2 million homes in typical conditions and 480,000 homes in peak periods, according to Vistra.

And Dominion Energy has indicated it is open to connecting a data center to the Millstone nuclear plant in Connecticut. The Dominion service region includes northern Virginia, the epicenter of the data center boom.

“We continue to explore that option,” CEO Robert Blue said on Dominion’s second-quarter earnings call. “We do clearly realize any co-location option is going to have to make sense for us, our potential counterparty and stakeholders in Connecticut.”

Kelly Trice, president of Holtec International, a privately held nuclear company headquartered in Florida, said the U.S. needs to start thinking more about balancing the power needs of data centers with those of all consumers. Holtec is working to restart the Palisades nuclear plant in Michigan and has also had conversations with tech companies about nuclear energy.

“Essentially, the hyperscalers and the data centers can take all the power and the consumer not get any of that if we’re not careful,” Trice told CNBC. “So the balance there, where the consumers actually get what is rightfully theirs too, is a factor.”

“The United States hasn’t really started wrestling [with] that yet,” Trice said. “But I think we’re getting close.”

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Coterra’s strong energy production allowed for big cash returns to shareholders

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In this photo illustration, a Coterra Energy Inc. logo is seen on a smartphone screen.

Pavlo Gonchar | SOPA Images | LightRocket | Getty Images

Coterra Energy missed Wall Street expectations for sales and earnings in the second quarter. However, production volumes and more importantly cash generation both came in ahead of expectations.

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Oil alliance OPEC+ could extend production cuts this weekend as focus shifts away from Middle East tensions, sources say

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The OPEC logo on the building of the Organization of the Petroleum Exporting Countries.

Thomas Coex | Afp | Getty Images

The oil-producing Organization of the Petroleum Exporting Countries and its allies could extend existing output cuts this week, delegates and analysts told CNBC, even as focus shifts from Middle East tensions to summer demand.

The group, collectively known as OPEC+, was set to convene in person in Vienna on June 1, but last week moved the encounter virtually to June 2.

OPEC+ producers are currently implementing a combined 5.86 million barrels per day of supply cuts. Just 2 million barrels per day of these cuts represent unanimous commitments under OPEC group policy, and expire at the end of this year.

The remainder are reduced voluntarily by a subset of the alliance. A cut of 1.66 million per barrel is in place until the end of 2024, and 2.2 million barrels per day of supplies have been trimmed until the end of the second quarter. Market participants are watching whether this latter cut will be extended for another quarter, amid projected demand hikes.

“Come June, China would be largely out of refinery maintenance, U.S. consumption is improving as summer moves closer, so June should already see negative crude balances. And then August is the peak month for tightness,” Viktor Katona, lead crude analyst at Kpler, told CNBC.

The OPEC+ coalition is also eyeing individual members’ quota compliance, asking overproducers to implement additional cuts. Iraq and Kazakhstan have detailed compensation plans.

Extension

Three OPEC+ delegates, who spoke anonymously because of the sensitivity of talks, told CNBC the 2.2 million-barrels-per-day supply reductions will likely be prolonged, with a fourth saying this is the scenario anticipated by the market. One delegate acknowledged the probable market tightness in the second half of the year, but noted that demand concerns persisted until only recently.

OPEC’s latest Monthly Oil Market Report of May projects a 2.25 million barrel-per-day increase in demand this year, while Paris-based International Energy Agency’s Oil Market Report of the same month points to just a 1.06 million-barrel-per-day demand hike.

“I think that the clever thing for OPEC+ would be to gradually unwind the voluntary cuts to limit the upside price pressure, to prevent refilling inflation,” Jorge Leon, senior vice president of Rystad Energy’s Oil Market Research, told CNBC. “However, I think that the market right now has priced in a full extension of the voluntary cuts. So I think that is what, probably, they will do.”

He added, “If they decide to fully extend the voluntary cuts, and there is perfect compliance, and they do the full compensation, and then, if, I think prices could reach closer to $100 per barrel this summer.”

Energy security concerns fueled global inflation in the wake of Russia’s invasion of Ukraine and were further stoked after the conflict in Gaza threatened a broader spillover in the oil-rich Middle East, while frequent maritime attacks by Yemen’s Houthi militants disrupted trade transit in the Red Sea.

A high-inflation environment and tight monetary policy in turn reined in oil demand, but central banks have signaled readiness to lower interest rates in the second half of the year.

Tamas Varga, analyst at PVM Oil Associates, told CNBC that the OPEC+ supply restrictions will likely remain in place for the third quarter, adding, “I also believe that the producer group will emphasize that anyone who did not comply with the quota will have to make amends. And I believe that OPEC+ will only ease the supply constraints when they see obvious signs of global oil inventories depleting.”

Kpler’s Katona aligned with the views, but noted that heavyweights Saudi Arabia, Russia and the United Arab Emirates, who participate in the voluntary reductions, could seek to scrap the latter curbs toward the end of the year.

“Further down the line into 2025, unwinding cuts might be challenging for prices as incremental production from Guyana, Brazil, Canada will saturate the markets,” he said, flagging new Floating Production Storage and Offloading facilities due to come online. “This year there’s no new FPSO in Guyana, whilst next year it starts up a new one in [third-quarter] 2025. Brazil, likewise, has one FPSO starting up this year whilst next year it will be a bonanza of new capacity.”

S&P Global Commodity Insights: We expect OPEC+ to extend cuts through year-end

Rising competing supplies have reduced the market prominence of OPEC+, one OPEC+ delegate acknowledged, while analysts signaled that the group’s ongoing output cuts allows unfettered producers to capture their market share.

Priced in

Oil prices have largely languished range-bound in the first half of the year, under ongoing threat of spikes from developments in the Middle East. Regional escalations could top prices with a risk premium of up to $10 per barrel, Rystad’s Jorge Leon noted – while OPEC+ delegates told CNBC that the situation in the Gaza Strip is still adding a little pressure, but that the market has already absorbed the majority of its effect.

Katona likewise noted that the Gaza crisis “will seemingly persist for longer than everyone expected but it doesn’t really have an imprint on OPEC+ coherence and policy.”                     

One OPEC+ delegate meanwhile said that the unexpected death of Iranian President Ebrahim Raisi represented a tragic accident that could not be interpreted as a risk to the market, especially given that his successor will likely pursue similar politics.

“I think the geopolitical risk premium has subsided and I think that the tension between Israel and Hamas will only support prices if it will have an obvious impact on oil production or oil flows, which might come in the form of the closure of the Strait of Hormuz, or attacks on oil infrastructure in the region, something which does not look plausible at the moment,” Varga said.

OPEC+ must also balance its relationship with the U.S., which has previously blasted the coalition’s supply cuts amid concerns over gasoline prices. The Biden administration last week said it will release 1 million barrels of gasoline from reserves in a bid to curb prices at the pump. The U.S. undertook similar crude releases from its Strategic Petroleum Reserve Stocks during the Covid-19 pandemic, but one OPEC+ delegate noted such measures are unlikely to have an impact beyond price relief during the summer. The U.S. typically seeks to replenish the emergency stockpile of its state reserves.

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Trump VP prospect Doug Burgum and GOP oil baron Harold Hamm are allies in business and politics

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Republican presidential candidate and former President Donald Trump shakes hands with North Dakota Gov. Doug Burgum as Vivek Ramaswamy, left, watches at a campaign rally at The Margate Resort in Laconia, New Hampshire, Jan. 22, 2024.

Jabin Botsford | The Washington Post | Getty Images

If former President Donald Trump taps North Dakota Gov. Doug Burgum to be his running mate, the biggest beneficiary of the partnership could be someone else entirely: Harold Hamm, the billionaire founder and executive chairman of shale oil drilling giant Continental Resources, who could end up with two powerful allies in a Trump White House.

Burgum’s ties to Hamm and the shale oil drilling giant he founded are complex. Continental is the largest oil and gas leaseholder in North Dakota, where oil and gas is the biggest industry by revenue.

The two men also have a friendship outside of business: Burgum recently contributed a rave review blurb to Hamm’s new memoir. And during his 2023 state of the state address, Burgum compared Hamm favorably to President Theodore Roosevelt, describing Hamm as a person “whose grit, resilience, hard work and determination has changed North Dakota and our nation.”

But Burgum has an even more personal link to Continental: Burgum’s family leases 200 acres of farmland in Williams County to the energy giant for the company to pump oil and gas, according to previously unreported business records and a federal financial disclosure report.

Burgum has made up to $50,000 in royalties since late 2022, while he’s been governor, from the deal with Continental Resources, according to his financial disclosure, details of which have not been reported.

Experts told CNBC that Burgum and his family business likely made thousands more from the agreement with Continental Resources since signing a contract with the company in 2009.

This link between Burgum and Continental highlights one of the potential risks for Trump of selecting a running mate who has lived most of his adult life in private.

Burgum has never been subjected to the kind of scrutiny that someone like Sen. Marco Rubio, R-Fla., has undergone and from which Rubio has emerged politically intact.

Burgum endorsed Trump in January, a month after he dropped out of the Republican primary for president. Since then, he has become an advisor to Trump on energy policy and joined a shortlist of contenders to be the former president’s running mate.

Hamm, meanwhile, is one of Trump’s biggest supporters in the industry. Burgum, Hamm and other industry advocates were reportedly at a meeting at Trump’s private Florida club, Mar-a-Lago, where the former president called on oil and gas executives to donate $1 billion to his campaign in exchange for his plan to roll back environmental regulations.

Hamm is co-hosting an event for Trump that’s sponsored by the former president’s political action committee, Make America Great Again Inc., on May 22, according to an invitation.

Continental Resources donated $1 million to the super PAC in April, according to Federal Election Commission records. Hamm gave $614,000 to the Trump 47 Committee in March.

Burgum’s oil deal with Continental

The original agreement between the Burgum Farm Partnership and Continental Resources was signed by Bradley Burgum, the governor’s late brother, according to a land lease reviewed by CNBC.

Burgum spokesman Mike Nowatzki told CNBC the contract was drawn up years before the governor was sworn into office in 2017.

“North Dakota is a leading energy producer, including the No. 3 oil producing state. Tens of thousands of families and mineral owners have similar arrangements,” Nowatzki said. “As the publicly available disclosures show: The cited agreement began many years before he became governor.”

Nowatzki did not answer specific questions about the deal, Burgum’s role with the family business or his relationship with Hamm.

A spokeswoman for both Continental Resources and Hamm did not respond to a request for comment. A spokesman for the Trump campaign did not respond to a request for comment.

CNBC obtained Burgum’s personal financial disclosure by a request to the Federal Election Commission. His business records were acquired through the North Dakota secretary of state’s office.

Data from North Dakota’s Minerals Department shows that the locations of the oil and gas wells matches the coordinates of Burgum’s family farm on his business records. The state’s data does not identify Burgum’s address, but the area where the farm and seven of Continental Resources wells are located is within a small township named Brooklyn.

All seven wells have been active since 2011, just two years after Burgum’s family signed an agreement with Continental Resources. The wells produced over 5,000 barrels of oil and thousands of cubic feet in natural gas in March alone, according to the latest data from Drilling Edge. It’s unclear how many of the seven wells are located directly on the Burgum property.

Burgum was elected governor in 2016 and reelected to a second term in 2020. He’s not running for reelection in 2024.

The Burgum Farm Partnership LLP, which oversees the family farm land in Williams County and Cass County, is worth between $500,001 and $1 million, according to the financial disclosure.

Doug Burgum is a managing partner of the Burgum Farm Partnership, and he signed the businesses’ latest annual report in March. Burgum’s financial disclosure says the governor is a non-managing member and the company is a “family investment” limited liability partnership.

The company’s annual report that was filed to the secretary of state’s office in April lists Burgum, his late brother’s two children, his sister, Barbara, and his own three adult children as managing partners of the family business.

The oil and gas land deal says Continental Resources provides the Burgum Farm Partnership 19% of the proceeds from the sales of oil and gas Continental sold after it is pumped from the Burgum property, according to the contract and experts who reviewed the records.

“The greater benefit is that the Burgum Farm Partnership does not have to invest any money to drill the wells, collect the hydrocarbons (no pipes, no tanks, no roads),” Edward Hirs, an energy fellow at the University of Houston, said in an email after reviewing the contract.

The royalty payments arrive in monthly and quarterly installments, according to the agreement.

The sun sets behind a pumpjack during a gusty night in Fort Stockton, Texas, March 24, 2024.

Brandon Bell | Getty Images

Experts note that landholders leasing their property to oil and gas companies can make thousands of dollars more beyond the royalties in bonuses and other payments.

“The company will usually pay the land owner a ‘bonus’ for signing the lease (usually hundreds or thousands of dollars per acre, depending on how hot the market might be),” said Jack Balagia, an adjunct professor at the University of Texas and former general counsel for Exxon Mobil. 

Ryan Kellogg, a professor at the University of Chicago who reviewed the contract, said the document does not disclose details of a bonus to the Burgum farm company, except to give a low range of how much was paid.

“The up-front bonus payment is not disclosed,” Kellogg said. “It’s just listed as ‘$10 and more’ where the ‘more’ is potentially significant. Bonuses are almost never disclosed in leases.”

The Burgum contract also says that the family business made money from Continental Resources through one initial down payment called “paid-up” on the lease, with no details provided on how much Burgum and his family saw from that part of the agreement.

“By paid-up, [we mean] a lease where all cash for the term of the lease is paid upfront, and by a rental form, we mean one with a down payment and rental payments once a year after that,” said Ted Borrego, an adjunct professor at the University of Houston Law Center.

Burgum drilling contract raises questions

Government ethics experts say the new details on Burgum’s Continental lease deal underscore the fact that if Burgum were to help implement energy policy in a Trump White House — either as his vice president or in a Cabinet position — his work could personally benefit the North Dakota governor and his family.

“There are potentially significant conflict of interest concerns with respect to Mr. Burgum’s oil and gas leases if Trump were to be reelected and Burgum selected to play an administration role” in implementing Trump’s energy policies, said Virginia Canter, chief ethics counsel for watchdog Citizens for Responsibility and Ethics in Washington.

Trump has promised that one of his first acts in office, if he is elected, will be to implement a “drill, baby, drill” energy policy and end delays in federal drilling permits and leases for American oil and natural gas production.

“A significant conflict of interest concern would arise, for example, if implementation of these policies would affect the value of Burgum’s leased property interests, his oil and gas leases or the royalties he receives from Continental Resources,” said Canter.

North Dakota Gov. Doug Burgum encourages voters to support Republican presidential candidate and former President Donald Trump during a campaign rally in the basement ballroom of The Margate Resort in Laconia, New Hampshire, Jan. 22, 2024.

Chip Somodevilla | Getty Images

Neither of Burgum’s two financial disclosures from his successful runs for governor reveal a land deal with Continental Resources. North Dakota requires candidates for state office to disclose only the names of businesses that do not act as their principal source of income. No other details are required to be disclosed.

Since Burgum first ran for governor in 2016, he’s disclosed to the North Dakota secretary of state’s office that he and his wife, Kathryn, have a financial interest in more than a dozen companies, including Burgum Farm Partnership.

But those three-page state records do not specify how much of a financial interest they have in these companies nor any money they make from those businesses. 

A candidate for president or Congress is required to disclose many more details, including a range of income from each of their assets during the previous 12 months.

Burgum’s federal disclosure report spans 26 pages and reveals scores of closely held LLCs, partnerships and assets. With Burgum’s net worth easily in the hundreds of millions, the Continental lease forms only a small part of his income streams.

Burgum and Trump aligned on energy

Ultimately, it may not matter to Trump whether Burgum has been fully vetted if the governor is the person he wants on his ticket.

For Trump, Burgum represents a key ally in the oil and gas business, as the former president looks to raise money from the industry’s executives.

Dan Eberhart, who runs oil and gas drilling company Canary, said a Trump/Burgum ticket could help to accomplish this.

“Choosing Burgum would bring more industry donors to Trump’s orbit,” Eberhart said in a recent interview.

“Nominating Burgum as VP would send a strong signal to the industry that we would have an important voice in a potential Trump administration,” he added.

President Donald Trump greets Harold Hamm after he was introduced by Hamm at the Shale Insight 2019 Conference in Pittsburgh, Oct. 23, 2019.

Leah Millis | Reuters

Government ethics watchdogs have also started to take notice of the relationship between Trump, Hamm, Burgum and others linked to the oil and gas industry.

“The fact that Mr. Burgum has an income producing, oil and gas lease arrangement with Continental Resources itself raises its own concerns, since Continental Resources’ executive chairman, Harold Hamm, recently participated with other oil and gas executives and Mr. Burgum in the Mar-a-Lago meeting Mr. Trump held last month seeking $1 billion in fundraising from those in attendance,” said Canter.

“Under these circumstances, Mr. Burgum seems to be uniquely positioned to benefit himself both financially and politically depending on what he is able to bring to the table that would serve the respective interests of Trump and Hamm,” she said.

Hamm’s company has had extensive business in North Dakota for over a decade, and the state is ranked in the top three states to produce oil.

In 2022, Hamm announced Continental Resources was investing $250 million into a pipeline that spanned 2,000 miles to capture carbon dioxide and pump it underground for storage in North Dakota. Last year, Hamm donated $50 million to a planned library in North Dakota honoring Roosevelt.

Hamm’s alliance with Burgum preceded a donation Continental Resources made to a PAC that backed the North Dakota governor when he ran for president. The company gave $250,000 to the pro-Burgum Best of America PAC in July, according to FEC filings.

Burgum’s gubernatorial campaign has regularly been backed by other executives in the oil and gas industry, according to data from the nonpartisan OpenSecrets.

Burgum’s successful campaign for governor in 2020 received more than $35,000 from those in the oil and gas industry. That amount is second only to the more than $1 million Burgum put into his campaign.

Correction: This story has been updated to reflect the correct spelling of Make America Great Again Inc. and the correct spelling of Ryan Kellogg’s name.

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AI could drive a natural gas boom as power companies face surging electricity demand

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A chimney from the Linden Cogeneration Plant is seen in Linden New Jersey April 22, 2022. 

Kena Betancur | View Press | Corbis News | Getty Images

Natural gas producers are planning for a significant spike in demand over the next decade, as artificial intelligence drives a surge in electricity consumption that renewables may struggle to meet alone.

After a decade of flat power growth in the U.S., electricity demand is forecast to grow as much as 20% by 2030, according to a Wells Fargo analysis published in April. Power companies are moving to quickly secure energy as the rise of AI coincides with the expansion of domestic semiconductor and battery manufacturing as well as the electrification of the nation’s vehicle fleet.

AI data centers alone are expected to add about 323 terawatt hours of electricity demand in the U.S. by 2030, according to Wells Fargo. The forecast power demand from AI alone is seven times greater than New York City’s current annual electricity consumption of 48 terawatt hours. Goldman Sachs projects that data centers will represent 8% of total U.S. electricity consumption by the end of the decade.

The surge in power demand poses a challenge for Amazon, Google, Microsoft and Meta. The tech companies have committed to powering their data centers with renewables to slash carbon emissions. But solar and wind alone may be inadequate to meet the electricity load because they are dependent on variable weather, according to an April note from consulting firm Rystad Energy.

“Economic growth, electrification, accelerating data center expansion are driving the most significant demand growth in our company’s history and they show no signs of abating,”

Robert Blue

Dominion Energy, Chief Executive Officer

Surging electricity loads will require an energy source that can jump into the breach and meet spiking demand during conditions when renewables are not generating enough power, according to Rystad. The natural gas industry is betting gas will serve as the preferred choice.

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Natural gas prices year to date

“This type of need demonstrates that the emphasis on renewables as the only source of power is fatally flawed in terms of meeting the real demands of the market,” Richard Kinder, executive chairman of pipeline operator Kinder Morgan, told analysts during the company’s first-quarter earnings in April.

“The primary use of these data centers is big tech and I believe they’re beginning to recognize the role that natural gas and nuclear must play,” Kinder said during the call. Kinder Morgan is the largest natural gas pipeline operator in the U.S. with 40% market share.

Natural gas is expected to supply 60% of the power demand growth from AI and data centers, while renewables will provide the remaining 40%, according to Goldman Sachs’ report published in April.

Gas demand could increase by 10 billion cubic feet per day by 2030, according to Wells Fargo. This would represent a 28% increase over the 35 bcf/d that is currently consumed for electricity generation in the U.S, and a 10% increase over the nation’s total gas consumption of 100 bcf/d.

“That’s why people are getting more bullish on gas,” said Roger Read, an equity analyst and one of the authors of the Wells Fargo analysis, in an interview. “Those are some pretty high growth rates for a commodity.”

The demand forecasts, however, vary as analysts are just starting to piece together what data centers might mean for natural gas. Goldman expects a 3.3 bcf/d increase in gas demand, while Houston-based investment bank Tudor, Pickering, Holt & Co. sees a base case of 2.7 bcf/d and a high case of 8.5 bcf/d.

Powering the Southeast boom

Power companies will need energy that is reliable, affordable and can be deployed quickly to meet rising electricity demand, said Toby Rice, CEO of EQT Corp., the largest natural gas producer in the U.S.

“Speed to market matters,” Rice told CNBC’s “Money Movers” in late April. “This is going to be another differentiator for EQT and natural gas to take a very large amount of this market share.”

Natural gas market looks oversupplied right now, says EQT CEO Toby Rice

EQT is positioned to become a “key facilitator of the data center build-out” in the Southeast, Rice told analysts on the company’s earnings call in April.

The Southeast is the hottest data center market in the world with Northern Virginia in the thick of the boom, hosting more data centers than the next five largest markets in the U.S. combined. Some 70% of the world’s internet traffic passes through the region daily.

The power company Dominion Energy forecasts that demand from data centers in Northern Virginia will more than double from 3.3 gigawatts in 2023 to 7 gigawatts in 2030.

Further south, Georgia Power sees retail electricity sales growing 9% through 2028 with 80% of the demand coming from data centers, said Christopher Womack, CEO of Georgia Power’s parent Southern Company, during the utility’s fourt-quarter earnings call in February.

“Economic growth, electrification, accelerating data center expansion are driving the most significant demand growth in our company’s history and they show no signs of abating,” Dominion CEO Robert Blue said during the company’s March investor meeting.

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EQT shares over the past year.

The surging power demand in the Southeast lies at the doorstep of EQT’s asset base in the Appalachian Basin, Rice said during the earnings call. Coal plant retirements and data centers could result in 6 bcf/d of new natural gas demand in EQT’s backyard by 2030, the CEO said.

EQT recently purchased the owner of the Mountain Valley Pipeline, which connects prolific natural gas reserves that EQT is operating and developing in the Appalachian Basin to southern Virginia. EQT is the only producer that can access the growing data center market through the pipeline, said Jeremy Knop, the company’s chief financial officer.

“I think we are very uniquely positioned in that sense,” Knop said during the call. Rice said the Southeast will become an even more attractive gas market than the Gulf Coast later in the decade. EQT is planning to expand capacity on the Mountain Valley Pipeline from 2 bcf/d to 2.5 bcf/d. The pipeline is expected to become operational in June.

The level of electricity demand could help lift natural gas prices out of the doldrums.

Prices plunged as much more than 30% in the first quarter of 2024 on strong production, lower demand due to a mild winter and historic inventory levels in the U.S. By 2030, prices could average $3.50 per thousand cubic feet, a 46% increase over the 2024 average price of $2.39, according to Wells Fargo.

Grid reliability worries

Dominion laid out scenarios in its 2023 resource plan that would add anywhere from 0.9 to 9.3 gigawatts of new natural gas capacity over the next 25 years. The power company said gas turbines will be critical to fill gaps when production drops from renewable resources such as solar. The turbines would be dual use and able to take clean hydrogen at some point.

“We’re building a lot of renewables, which all of our customers are looking for, but we need to make sure that we can operate the system reliably,” Blue told analysts during Dominion’s earnings call Thursday.

Renewables will play a major role in meeting the demand but they face challenges that make gas look attractive through at least 2030, Read, the Wells Fargo analyst, told CNBC.

An all of the above strategy is the only thing that we see as the way to maintain the reliability and the affordability that our customers count on.”

Lynn Good

Duke Energy, Chief Executive Officer

Many of the renewables will be installed in areas that are not immediately adjacent to data centers, he said. It will take time to build power lines to transport resources to areas of high demand, the analyst said.

Another constraint on renewables right now is the currently available battery technology is not efficient enough to power data centers 24 hours a day, said Zack Van Everen, director of research at investment Tudor, Pickering, Holt & Co.

Nuclear is a potential alternative to gas and has the advantage of providing carbon free energy, but new advanced technology that shortens typically long project timelines is likely a decade away from having a meaningful impact, according to Wells Fargo.

Richard Kinder, executive chairman of pipeline operator Kinder Morgan, said significant amounts new nuclear capacity will not come online for the foreseeable future, and building power lines to connect distant renewables to the grid will take years. This means natural gas has to play an important role for years to come, Kinder said during the company’s earnings call in April.

“I think acceptance of this hypothesis will become even clearer as power demand increases over the coming months and years and it will be one more significant driver of growth in the demand for natural gas that will benefit all of us in the midstream sector,” Kinder said.

Environmental impact

Any expansion of natural gas in meeting U.S energy demand is likely to be met with opposition from environmental groups who want fossil fuels to be phased out as soon as possible.

Goldman Sachs forecast carbon emissions from data centers could more than double by 2030 to about 220 million tons, or 0.6% of global energy emissions, assuming natural gas provides the bulk of the power.

Virginia has mandated that all carbon-emitting plants be phased out by 2045. Dominion warned in its resource plan that the phase out date potentially raises system reliability and energy independence issues, with the company relying on purchasing capacity across state lines to meet demand.

Duke Energy CEO Lynn Good said natural gas “can be a difficult topic,” but the fossil fuel is responsible for 45% of the power company’s emissions reductions since 2005 as dirtier coal plants have been replaced. Good said electricity demand in North Carolina is growing at a pace not seen since the 1980s or 1990s.

“As we look at the next many years trying to find a way to expand a system to approach this growth, I think natural gas has a role to play,” Good said at the Columbia Global Energy Summit in New York City in April. The CEO said natural gas is needed as a “bridge fuel” until more advanced technology comes online.

“An all of the above strategy is the only thing that we see as the way to maintain the reliability and the affordability that our customers count on,” Good said.

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‘Iran is in for the long haul’ with oil tanker hijacks, expert says, as U.S. considers more sanctions

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Iranian soldiers take part in an annual military drill in the coast of the Gulf of Oman and near the strategic Strait of Hormuz.

Anadolu | Anadolu | Getty Images

The containership MSC Aries seized by Iran over the weekend marked at least the sixth vessel hijacked by Iran and its proxies in response to the Israel-Gaza war, and it’s adding to the challenges to longstanding freedom of navigation principles that maritime shipping relies on.

Before this weekend’s tanker seizure, the last vessel Iran hijacked was the St. Nikolas on January 1. According to U.S. Naval Forces Central Command, that brought the total number of vessels being held to five, and over 90 crew members hostage. Previous to that, the Iranian-backed Houthis hijacked The Galaxy Leader on November 19.

The latest development has shipping and energy experts bracing for a long-term timeline of uncertainty.

“Iran is in this for the long haul,” said Samir Madani, co-founder of Tankertrackers.com, an independent online service that tracks and reports crude oil shipments in several geographical and geopolitical points of interest.

The MSC Aries was identified by Iran as having a link to Israel. The containership has a carrying capacity of 15,000-TEUs (twenty-foot equivalent containers). MSC leases the Aries from Gortal Shipping, an affiliate of Zodiac Maritime, which is partly owned by Israeli businessman Eyal Ofer.

MSC declined to comment directly to CNBC.

In a statement released by MSC on Wednesday, it said the crew members were safe and discussions with Iranian authorities were underway to secure their earliest release and to have the cargo discharged.

Madani said he does not expect a quick release. “They will hold the MSC Aries for a long period. Iran has been holding some tankers for about a year, if not longer now,” he said.

According to Tankertracker information, Madani said the vessel is being held in the Khuran Straits, not too far from three other tankers Iran hijacked: the Advantage Sweet, Niovi, and St. Nikolas.

A Planet Labs satellite image of the location of the MSC Aries and other tankers recently hijacked by Iran.

Planet Labs PBC

As the U.S. considers more sanctions against Iran in response to its recent attack on Israel, Iran has been using the hijacked ships as a means of sanctions retaliation.

“Iran has already seized the Kuwaiti oil that was onboard the Advantage Sweet and has been loaded onto their VLCC supertanker the Navarz. Iran chose to do this as a way to compensate for sanctions,” Madani said.

While the Niovi was empty at the time of the seizure, the St. Nikolas is filled with a million barrels of Iraqi oil.

Treasury Secretary Janet Yellen said on Tuesday that the government may do more to prevent Iran’s ability to export oil despite U.S. sanctions. China’s purchases of Iranian oil in recent years have allowed Iran to keep a positive trade balance.

According to the U.S. Energy Information Agency, China, the world’s largest importer of crude oil, imported 11.3 million barrels per day of crude oil in 2023, 10% more than in 2022. Iran ranked second in oil exports to China behind Russia. Customs data indicates that China imported 54% more crude oil (1.1 million b/d) from Malaysia in 2023 than in 2022, with industry analysts speculating that much of the oil shipped from Iran to China was relabeled as originating from countries such as Malaysia, the United Arab Emirates, and Oman to avoid U.S. sanctions.

The markets continues to assess the risk of further escalation in the military tensions between Israel and Iran, which could lead to a disruption in the Strait of Hormuz, through which about 30% of the world’s seaborne oil passes, according to JPMorgan. On Tuesday, oil edged higher amid talk of sanctions.

An Iranian blockade would supercharge oil prices, but the risk is low given that the strait has never been closed off despite many threats by Tehran to do so over the past four decades, according to JPMorgan.

“They can’t close the Strait of Hormuz, but they can do significant damage to energy infrastructure, to vessels in the region,” RBC’s head of global commodity strategy and Middle East and North Africa research, Helima Croft, told CNBC on Monday, referring to Iran’s capabilities.

“While I can’t imagine Iran would want to fill up their anchorage with vessels, they want to keep the waters in a constant state of chaos,” Madani said. But with a closure, he said, “They would shoot themselves in the foot since their biggest client is China.”

Andy Lipow, president of Lipow Oil Associates, says the closure of the Strait of Hormuz would result in a spike of Brent crude oil prices to the $120 to $130 range. “This would strain ties with China and India who purchase a significant amount of Persian Gulf oil to meet much of their energy demand.”

Lipow also said Iran might be reluctant to shut the waterway for fear of antagonizing Saudi Arabia, Kuwait and Iraq, who depend on the strait being open for most of their oil exports. The bigger immediate fear in the oil market, he said, is that the attack by Iran on Israeli territory leading to a counterattack by Israel on Iran damaging oil-producing and exporting facilities.

Kevin Book, managing director of ClearView Energy Partners, says the markets need to keep an eye on sanctions from both the US and UN potentially.

In a note to clients, ClearView highlighted that the House of Representatives added several Iran sanctions bills to its calendar for consideration this week, under suspension rules, including new sanctions on Iranian oil exports to China. Book said the House was considering 11 bills in all in response to Iran’s attack on Israel.

“We think most if not all bills could garner (notionally) veto-proof bipartisan support,” the note said. “Passage requires a two-thirds majority of all members present and voting.”

Israel has also asked the U.N. to reinstate multilateral sanctions lifted by the Iran nuclear deal, but for this to happen, France, Germany and the U.K., parties to the nuclear deal, would have to agree. “There are many risks unfolding. The forest is on fire,” Book said.

Sen. Dean Sullivan talks impact of Iran's strikes on Israel and what it means for crude oil prices

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Big Oil’s green-bashing stokes backlash as campaigners hit out at ‘talking points from the 1970s’

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Saudi Aramco President & CEO Amin Nasser speaks during the CERAWeek oil summit in Houston, Texas, on March 18, 2024.

Mark Felix | Afp | Getty Images

Top oil executives have been sharply criticized for pushing back against the viability of the clean energy transition at a U.S. conference, with campaigners denouncing an industry claim that the shift away from fossil fuels is “visibly failing on most fronts.”

Speaking during a panel interview on Monday at the annual CERAWeek energy conference in Houston, Texas, Saudi Aramco chief executive Amin Nasser said that a transition strategy reset was “urgently needed.”

The CEO of the world’s largest energy company proposed that policymakers abandon the “fantasy” of phasing out oil and gas and instead “adequately” invest in fossil fuels to reflect growing demand. Aramco and Saudi ministry officials have previously advocated for ongoing investment in hydrocarbons to avoid energy shortages until renewables can fully meet global energy demands.

Nasser’s comments drew applause from the audience at CERAWeek — an annual energy conference by S&P Global that’s known as the “industry’s Super Bowl.”

Other oil and gas executives at the event echoed Nasser’s views, but spoke less directly about the state of the energy transition.

Shell CEO Wael Sawan said government bureaucracy in Europe was slowing the necessary development of clean energy, according to Reuters. Separately, Exxon Mobil CEO Darren Woods on Monday said that demand for petroleum products is “still very, very healthy.”

“So, I think one of the things the policy to date and a lot of the narrative has been very focused on is the supply side of the equation and hasn’t addressed the demand side of the equation. And the impact that price has on demand,” Woods told CNBC’s “Squawk on the Street.”

“At the same time, the cost of converting and moving to a lower-carbon society, if that cost is too high for consumers to bear, they won’t pay. And we’ve seen that play itself out in Europe, with some of the farm protests and the yellow vest protests a year or so ago,” he added.

Campaigners have hit out at the oil industry’s claims this week.

“The fossil fuel industry continues to make distorted claims about our energy future,” Jeff Ordower, North America director at 350.org — a U.S.-based group focused on the global energy transition — said in a statement on Tuesday.

“They work night and day to torpedo a transition to renewable energy and then have the audacity to critique the slowness of the transition itself,” Ordower said. “CERAWeek should highlight a global vision toward a clean and equitable future, and instead, we get talking points from the 1970s.”

Aramco, Exxon Mobil and Shell were not immediately available to comment when contacted by CNBC on Wednesday.

IEA vs. OPEC

The International Energy Agency has previously said it expects global oil, gas and coal demand to peak by 2030 — a forecast that Aramco’s Nasser rejected at CERAWeek. The energy watchdog said in October last year that the transition to clean energy is not only happening, but is “unstoppable.”

“It’s not a question of ‘if’, it’s just a matter of ‘how soon’ – and the sooner the better for all of us,” IEA Executive Director Fatih Birol said in a statement.

The oil-producing Organization of the Petroleum Exporting Countries, which disagrees with the IEA on its outlook for oil demand growth, said earlier this month that it still expects relatively strong growth in global oil demand for both 2024 and 2025.

Participants are seen at the Innovation Agora of the CERAWeek in Houston, Texas, the United States, on March 18, 2024. CERAWeek, known as a superbowl forum in the global energy industry, kicked off Monday in Houston of the U.S. state of Texas, with topics covering the entire energy spectrum but themed on multidimensional energy transition in four fields: markets, climate, technology and geopolitics.

Xinhua News Agency | Xinhua News Agency | Getty Images

Policymakers have also renewed their focus on energy supply security in the wake of Russia’s full-scale invasion of Ukraine and the Israel-Hamas war.

It is in this context that oil and gas executives have repeatedly sought to fend off climate criticism, claiming that Big Oil is not to blame for the climate crisis and warning that it won’t be possible to keep everyone happy in the shift away from fossil fuels.

The burning of fossil fuels such as coal, oil and gas is the chief driver of the climate crisis.

“It’s no surprise to see misleading claims like this coming at CERAWeek, because fossil fuel companies are the biggest cause of the climate crisis, and their continued political influence is the biggest obstacle to solving it,” David Tong, global industry campaign manager at advocacy group Oil Change International, told CNBC via email.

“Oil and gas companies are deliberately slowing and blocking a rapid fossil fuel phase-out with the types of dangerous distractions they are peddling this week in Houston,” Tong said.

‘There’s really no debate’

Some energy companies have scaled back their greenhouse gas reduction targets in recent months.

Activist investors have put pressure on fossil fuel companies to further align their emission reduction targets with the landmark 2015 Paris Agreement, while some have urged firms to scale back on green pledges and instead lean into their core oil and gas businesses.

“What we are seeing now is a desperate attempt from the oil and gas industry to stay relevant and to double down on their old business model despite knowing the products they’ve sold us for decades are responsible for the climate crisis,” Josh Eisenfeld, corporate accountability campaign manager at Earthworks, an environmental non-profit based in Washington D.C., told CNBC via email.

“They’ve failed to evolve their business into one that is compatible with what science tells us must be done to avoid a climate catastrophe. There’s really no debate — science has made it abundantly clear what needs to be done and paramount to that is a transition away from fossil fuels,” Eisenfeld said. “To think otherwise is delusional,” he added.

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The North Sea could become a ‘central storage camp’ for carbon waste. Not everyone likes the idea

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The receiving dock at the Northern Lights carbon capture and storage project, controlled by Equinor ASA, Shell Plc and TotalEnergies SE, at Blomoyna, Norway, on Friday, Jan. 19, 2024.

Bloomberg | Bloomberg | Getty Images

Norway’s government wants to show the world it is possible to safely inject and store carbon waste under the seabed, saying the North Sea could soon become a “central storage camp” for polluting industries across Europe.

Offshore carbon capture and storage (CCS) refers to a range of technologies that seek to capture carbon from high-emitting activities, transport it to a storage site and lock it away indefinitely under the seabed.

The oil and gas industry has long touted CCS as an effective tool in the fight against climate change and polluting industries are increasingly looking to offshore carbon storage as a way to reduce planet-warming greenhouse gas emissions.

Critics, however, have warned about the long-term risks associated with permanently storing carbon beneath the seabed, while campaigners argue the technology represents “a new threat to the world’s oceans and a dangerous distraction from real progress on climate change.”

Norway’s Energy Minister Terje Aasland was bullish on the prospects of his country’s so-called Longship project, which he says will create a full, large-scale CCS value chain.

“I think it will prove to the world that this technology is important and available,” Aasland said via videoconference, referring to Longship’s CCS facility in the small coastal town of Brevik.

“I think the North Sea, where we can store CO2 permanently and safely, may be a central storage camp for several industries and countries and Europe,” he added.

Storage tanks at the Northern Lights carbon capture and storage project, controlled by Equinor ASA, Shell Plc and TotalEnergies SE, at Blomoyna, Norway, on Friday, Jan. 19, 2024.

Bloomberg | Bloomberg | Getty Images

Norway has a long history of carbon management. For nearly 30 years, it has captured and reinjected carbon from gas production into seabed formations on the Norwegian continental shelf.

It’s Sleipner and Snøhvit carbon management projects have been in operation since 1996 and 2008, respectively, and are often held up as proof of the technology’s viability. These facilities separate carbon from their respective produced gas, then compress and pipe the carbon and reinject it underground.

“We can see the increased interest in carbon capture storage as a solution and those who are skeptical to that kind of solution can come to Norway and see how we have done in at Sleipner and Snøhvit,” Norway’s Aasland said. “It’s several thousand meters under the seabed, it’s safe, it’s permanent and it’s a good way to tackle the climate emissions.”

Both Sleipner and Snøhvit projects incurred some teething problems, however, including interruptions during carbon injection.

Citing these issues in a research note last year, the Institute for Energy Economics and Financial Analysis, a U.S.-based think tank, said that rather than serving as entirely successful models to be emulated and expanded, the problems “call into question the long-term technical and financial viability of the concept of reliable underground carbon storage.”

‘Overwhelming’ interest

Norway plans to develop the $2.6 billion Longship project in two phases. The first is designed to have an estimated storage capacity of 1.5 million metric tons of carbon annually over an operating period of 25 years — and carbon injections could start as early as next year. A possible second phase is predicted to have a capacity of 5 million tons of carbon.

Campaigners say that even with the planned second phase increasing the amount of carbon stored under the seabed by a substantial margin, “it remains a drop in the proverbial bucket.” Indeed, it is estimated that the carbon injected would amount to less than one-tenth of 1% of Europe’s carbon emissions from fossil fuels in 2021.

The government says Longship’s construction is “progressing well,” although Aasland conceded the project has been expensive.

“Every time we are bringing new technologies to the table and want to introduce it to the market, it is having high costs. So, this is the first of its kind, the next one will be cheaper and easier. We have learned a lot from the project and the development,” Aasland said.

“I think this will be quite a good project and we can show the world that it is possible to do it,” he added.

Workers at an entrance to the CO2 pipeline access tunnel at the Northern Lights carbon capture and storage project, controlled by Equinor ASA, Shell Plc and TotalEnergies SE, at Blomoyna, Norway, on Friday, Jan. 19, 2024.

Bloomberg | Bloomberg | Getty Images

A key component of Longship is the Northern Lights joint venture, a partnership between Norway’s state-backed oil and gas giant Equinor, Britain’s Shell and France’s TotalEnergies. The Northern Lights collaboration will manage the transport and storage part of Longship.

Børre Jacobsen, managing director for the Northern Lights Joint Venture, said it had received “overwhelming” interest in the project.

“There’s a long history of trying to get CCS going in one way or another in Norway and I think this culminated a few years ago in an attempt to learn from past successes — and not-so-big successes — to try and see how we can actually get CCS going,” Jacobsen told CNBC via videoconference.

Jacobsen said the North Sea was a typical example of a “huge basin” where there is a lot of storage potential, noting that offshore CCS has an advantage because no people live there.

A pier walkway at the Northern Lights carbon capture and storage project, controlled by Equinor ASA, Shell Plc and TotalEnergies SE, at Blomoyna, Norway, on Friday, Jan. 19, 2024.

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“There is definitely a public acceptance risk to storing CO2 onshore. The technical solutions are very solid so any risk of leakage from these reservoirs is very small and can be managed but I think public perception is making it challenging to do this onshore,” Jacobsen said.

“And I think that is going to be the case to be honest which is why we are developing offshore storage,” he continued.

“Given the amount of CO2 that’s out there, I think it is very important that we recognize all potential storage. It shouldn’t actually matter, I think, where we store it. If the companies and the state that controls the area are OK with CO2 being stored on their continental shelves … it shouldn’t matter so much.”

Offshore carbon risks

A report published late last year by the Center for International Environmental Law (CIEL), a Washington-based non-profit, found that offshore CCS is currently being pursued on an unprecedented scale.

As of mid-2023, companies and governments around the world had announced plans to construct more than 50 new offshore CCS projects, according to CIEL.

If built and operated as proposed, these projects would represent a 200-fold increase in the amount of carbon injected under the seafloor each year.

Nikki Reisch, director of the climate and energy program at CIEL, struck a somewhat cynical tone on the Norway proposition.

“Norway’s interpretation of the concept of a circular economy seems to say ‘we can both produce your problem, with fossil fuels, and solve it for you, with CCS,'” Reisch said.

“If you look closely under the hood at those projects, they’ve faced serious technical problems with the CO2 behaving in unanticipated ways. While they may not have had any reported leaks yet, there’s nothing to ensure that unpredictable behavior of the CO2 in a different location might not result in a rupture of the caprock or other release of the injected CO2.”

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